Fracturing is a common stimulation method for increasing the production of hydrocarbons from subterranean formations penetrated by an oil, gas or geothermal well and is particularly suitable in the production of fluids and natural gas from low permeability formations. Typically in hydraulic fracturing, a fracturing fluid containing a proppant is injected into the well at a pressure which is sufficient to create or enlarge fractures within the subterranean formation. The proppant holds the fracture open during the recovery of hydrocarbons from the fractured formation.
Typically, the subterranean formation has a plurality of distinct production zones of interest. During production of fluids from the well, it usually is desirable to establish communication with only the zones of interest such that stimulation treatments do not inadvertently flow into a non-productive zone or a zone of diminished interest, Selective stimulation becomes pronounced as the life of the well declines and productivity of the well decreases.
With subterranean formations having multiple production zones of interest, the casing in a zone of interest, after being perforated and stimulated, must be hydraulically isolated before another zone of interest can be exploited. Isolation of zones often consists of inserting a mechanical plug below the zone of interest. The plug hydraulically isolates that portion of the well from a lower portion (or the rest) of the well. The isolation of the lower zone ensures that fracturing fluid pumped into the well is directed to the zone of interest.
Typically, fracture growth proceeds in those areas of the formation which exhibit the least amount of stress. As the fracture extends through the formation, it is not uncommon for the fracture to become misaligned from its original orientation, i.e., the orientation created when the fracture was initiated.
Near-wellbore tortuosity is the result of complex fracture geometry immediately surrounding the wellbore and can be caused by various factors including (a) misalignment of the wellbore or perforations with the far-field preferred fracture plane causing gradual or sharp fracture curvature in the near-wellbore region; (b) initiation of multiple fractures that compete for fracture width; (c) intersection of the hydraulic fracture with natural or drilling-induced fractures; or (d) fracture growth between the cement sheath and casing or cement sheath and formation due to inadequate cementing.
Tortuosity has been one of the biggest challenges for shale and tight gas hydraulic fracturing treatments, leading to high near-wellbore friction pressures, premature screenouts, reduced treating rates and poor production results. Several solutions have been applied with varying levels of success, but often result in nothing more than a frustrating attempt.
In light of the tortuosity of the pathway of the fracture, wellbore fluids require higher pumping rates and pressures in order that the fluid may surpass frictional forces created by the path. A common method to improve injection pressure prior to the fracturing treatment has been to pump small volumes (typically less than 10 bbls) of hydrochloric (HCl) or organic acid as “spearheads” in front of the fracturing treatment for the purpose of dissolving carbonate material and other soluble materials plugging the perforations.
High tortuosity can severely impact the effectiveness of multi-zone hydraulic fracturing treatments. In some cases, recovery of fluids from a zone is prohibited in light of the expense and time in combating tortuosity. In such cases, despite the zone having a promising return of fluid, the operator may make no attempt to recover any fluid from the zone. In other cases, a zone having the potential of high fluid return is sealed and isolated before the maximum amount of fluid is recovered.
High tortuosity during a fracture treatment further increases the surface treating pressure and consequently the injection pressure and hydraulic horsepower required to perform the fracturing treatment. Typically at in-situ conditions when stresses re-orient the direction of the fracture, increased pressure is needed in order to pump fluids into the fractures. This is especially the case when the well being treated is tight and/or likely to exhibit fractures with high tortuosity. In some cases, the required surface treating pressure for fracturing may exceed the surface equipment limitations, preventing a fracturing treatment from being performed.
Tortuosity also increases the risk of a premature screenout (early job termination) due to proppant bridging in the near-wellbore region. For this reason, the concentration of proppant may be lowered than what would otherwise be desired in order to avoid an early screenout, premature job termination and costly clean-out operation of the proppant from the wellbore before the fracturing of the next zone can be performed. The choking effect attributable to the complex fracture geometry near the wellbore can also significantly reduce productivity of the well.
Traditional methods of mitigating pre-existing tortuosity problems have included the pumping of proppant slugs (such as sand slugs) and/or viscous fluids into the fracture, re-perforating the fracture and sand-jetting. The most common have been the use of proppant slugs to either erode the fracture system or plug the less-conductive fractures and the pumping of highly viscous fluids to create extra fracture width. With both of these techniques, the proppant slug or viscous fluid is injected at fracturing rate and pressure and is proceeded by a step-down diagnostic injection/pressure falloff test to measure the amount of remaining tortuosity. The risk of screenout is often increased by pumping of proppant slugs. This may result in a costly and time-consuming clean-out in order to remove the sand from the wellbore before fracturing operations may be resumed. In severe cases where little or no improvement is shown, the perforated interval is isolated or abandoned and a new interval perforated with a different method with the hope of creating less tortuosity. The process is logistically complicated and requires tremendous time and the introduction of a high volume of fluid into each interval to be fractured.
Alternatives have therefore been sought for fracturing subterranean formations in multiple zones wherein at least one of the zones is impacted by high tortuosity. It is desirable that alternatives developed will not only improve fracturing efficiency but further be more operationally efficient by requiring less time and less expenditure than those presently offered.